1. Field of the Invention
This invention relates generally to the reduction of air and land pollution including thermal pollution resulting from the extraction of hydrocarbon fuels from a body of fixed fossil fuels in subsurface formations such as oil shale, and in particular to a method and apparatus for reducing greenhouse gases and residual heat in situ during and after the extraction of oil and gas from oil shale in situ utilizing any extraction process thereof. The invention also is applicable to heavy oil, aging wells, coal, lignite, peat and tar sands and may also be applied above ground in a batch or continuous type process. It may also be applied during and after the extraction of contaminants or residue from a body of fixed earth or from a vessel utilizing electrical energy and critical fluids (CF).
2. Description of Related Art
Oil shale, also known as organic rich marlstone, contains organic matter comprised mainly of an insoluble solid material called kerogen. Kerogen decomposes during pyrolysis into kerogen oil and hydrocarbon gases (or oil and gas), which can be used as generator fuels or further refined into transportation fuels, petrochemicals, or products. Shale oil and hydrocarbon gas (typically methane, Ch4) can be generated from kerogen by a pyrolysis process, i.e. a treatment that typically consists of heating oil shale to elevated temperatures, typically 300° to 500° C. Prior to pyrolysis, kerogen products at room temperature have substantial portions of high viscosity non-transformed material such that they cannot be accessed within the rock/sand matrix. After pyrolysis and removal the shale oil is refined into usable marketable products. Early attempts to process bodies of oil shale in situ by heating the kerogen in the oil shale, for example, using RF energy, injecting super-heated steam, hot liquids or other materials or by fire flooding into the oil shale formation, have not been economically viable even if fundamentally feasible (which some were not). Early and current attempts to process bodies of oil shale above ground to obtain the oil and gas in the oil shale, for example, by mining, crushing and heating the shale in a batch or continuous retort furnace, have not been environmentally feasible nor economically viable.
The in situ processes typically leave large amounts of residual energy and residual hydrocarbons in the ground which has unknown effects on the landscape and ecology and can be considered “wasted” energy. These processes also typically require large amounts of electrical energy which is usually provided by a power plant, either local or remote. The power plants may be fueled by fossil fuels such as coal or oil which produce greenhouse gases. This invention aims to optimize energy usage while minimizing both thermal, atmospheric (including “greenhouse gas”) and surface pollution. A closed loop or semi-closed type process is envisioned.
It is well known to use carbon dioxide for enhanced or tertiary oil recovery by injecting carbon dioxide into existing reservoirs in order to pressurize them and maximize the output of oil and gas. This process has met with limited success and does not purpose to capture or sequester significant amounts of CO2 in the reservoir.
Critical fluids are compounds at temperatures and pressures approaching or exceeding the thermodynamic critical point of the compounds. These fluids are characterized by properties between those of gases and liquids, e.g. diffusivities are much greater than liquids, but not as great as gases and viscosity is lower than typical liquid viscosities. Density of critical fluids is a strong function of pressure. Density can range from gas to liquid, while the corresponding solvent properties of a critical fluid also vary with temperature and pressure which can be used to advantage in certain circumstances and with certain methods.
Many techniques have been attempted or proposed to heat large volumes of subsurface formations (coal, lignite, shale, tar sands) in situ using electric resistance, gas burner heating, steam injection and electromagnetic energy such as to obtain oil and gas. For example, resistance type electrical elements have been positioned down a borehole via a power cable to heat the shale via conduction.
U.S. Pat. No. 4,140,179 issued Feb. 20, 1979 to Raymond Kasevich, et al. and assigned to Raytheon Company of Waltham, Mass. discloses a system and method for producing subsurface heating of a formation comprising a plurality of groups of spaced RF energy radiators (dipole antennas) extending down boreholes to oil shale. The antenna elements must be matched to the electrical conditions of the surrounding formations.
U.S. Pat. No. 4,508,168, issued Apr. 2, 1985 to Vernon L. Heeren and assigned to Raytheon Company, is incorporated herein by reference and describes an RF applicator positioned down a borehole supplied with electromagnetic energy through a coaxial transmission line whose outer conductor terminates in a choking structure comprising an enlarged coaxial stub extending back along the outer conductor. However, this approach by itself requires longer application of RF power and more variation in the power level with time. The injection of critical fluids (CF) will reduce the heating dependence, due solely on RF energy, simplifying the RF generation and monitoring equipment and reducing electrical energy consumed. The same benefit of CF is true if simpler electrical resistance heaters are used in place of the RF. Also, the injection of critical fluids (CF) increases the total output of the system, regardless of heat temperature or application method, due to its dilutent and carrier properties.
U.S. Patent Application Publication No. 2007-0137852 A1 published Jun. 21, 2007 and U.S. Patent Application Publication No. 2007-0137858 A1, published Jun. 21, 2007, describe an apparatus and method for extraction of hydrocarbon fuels or contaminants using RF energy and critical fluids, and they are incorporated by reference herein. While other in situ methods project years of heating by conduction, cracking and vaporization to get oil from shale, using RF energy to heat the shale and the critical fluid for forced convection and extraction reduces the time of production to weeks or months. The reduction in time also reduces the total amount of heat conducted to the surrounding formation after primary heating, improving the prevention of migration of liberated hydrocarbons. The RF/CF processes causes cracking of the kerogen at approximately 300° C. (a temperature lower than many other methods) and then use of CO2's partially miscible benefits further reduces the cracking temperature and viscosity and increases the diffusivity and ability to get the oil compounds to the surface at low temperature.
Therefore, electromagnetic energy is delivered via an antenna or microwave applicator similar to U.S. Pat. No. 4,196,329, issued Apr. 1, 1980 to Howard J. Rowland, et al., and assigned to Raytheon Company. The antenna is positioned down a borehole via a coaxial cable or waveguide connecting it to a high-frequency power source on the surface. Shale heating is accomplished by radiation and dielectric absorption of the energy contained in the electromagnetic (EM) wave radiated by the antenna or applicator. This is superior to more common resistance heating which relies solely on conduction to transfer the heat. It is superior to steam heating which requires large amounts of water and energy present at the site and also relies on conduction.
All of these heating methods leave residual heat and residual hydrocarbons in the formation after the processing is completed. The heat could be used to partially power the ongoing operation, reducing total energy consumption while removing part or all of the heat in the formation along with any associated thermal pollution. All of these methods also leave significant amounts (50-70%) of residual hydrocarbon in the formation. In most instances these hydrocarbons are now liberated and mobile and able to migrate toward undesirable areas such as aquifers, causing pollution. The period of mobility is related to many site specific and process specific factors, including primarily residual heat and the amount and type of residual oil. The longer the residual heat remains and the farther reaching it is, the higher the probability of residual oil and gas migration into other undesirable and unknown areas. Likewise, the more residual oil, and the lighter it is (thinner and more refined) the higher the probability of migration into undesirable and unknown areas.
The process described in U.S. Pat. Nos. 4,140,179 and 4,508,168 and other methods, using for example resistance heaters, requires a significant amount of electric power to be generated at the surface to power the process and does not provide an active transport method for removing the valuable hydrocarbon products as they are formed and transporting them to the surface facilities. Carbon Dioxide (CO2) or another critical fluid, which also acts as an active transport mechanism, for both products and heat can potentially be capped in the shale after the extraction is complete thereby reducing greenhouse gases released to the atmosphere. The CO2, utilized by the critical fluids process, can originate in production processes, gas wells, or be captured from the effluent of various industrial plants including power plants. It is envisioned that the onsite power plant that is powering the actual extraction process becomes a primary source of the CO2 required for the process.
CO2 sequestering has long been thought of as a desirable method for prevention and removal of greenhouse gases from the earth's atmosphere. With the goal of preventing or reducing global warming, CO2 sequestering aims to reduce CO2 emissions to the atmosphere at their source, such as CO2 effluent from power plants and other large CO2 producers. On a larger scale, removing excess CO2 from the earth's atmosphere theoretically would also significantly contribute to the reduction of greenhouse gases.
There are many studies and schemes surrounding this subject, but most are hampered by the mobility of CO2. CO2 is a gas, and as such, is highly mobile. Like any gas under pressure, it flows to the point of lowest pressure, looking to escape back to the atmosphere, or other places with-in the formation where the pressure is lowest. This is a basic physical property of a gas, and particularly of a gas under pressure. Of the thousands of potential reservoirs in the US alone, only 2% to 30% are deemed potentially suitable for CO2 sequestering, primarily due to this ability to escape. Experts in the field disagree on the potential for sequestering, as evidenced by the large disparity in suitable reservoirs, but most agree on the same basic mechanism. A suitable reservoir must have adequate porosity to accept the CO2 and adequate strength and stability to contain it once injected. Typical reservoirs include abandoned coal mines, aging or abandoned oil wells, shale deposits, salt mines, lake beds, coal mines, deep sea, etc. Most are deemed inadequate because the porosity that makes them attractive on one hand, ultimately leads to the release of CO2 on the other hand.
Even those potential reservoirs with reasonable porosity (i.e. they have sufficient capacity) will release substantial portions of the CO2 over a period of time depending on the site conditions and pressure of the CO2 due to that porosity. Some methods include injection of the C02 into a reservoir through abandoned oil wells, and then rely on well known well capping methods, such as cementing and mechanical sealing. Likewise, some formations that are acceptable for strength and leak containment lack the porosity to accept a significant amount of CO2 unless it is pressurized to several atmospheres which increases the likelihood it will eventually escape. In order for these sites and others to be suitable for sequestering, the CO2 must be chemically and/or physically bound to the formation.
U.S. Pat. No. 6,890,497 issued May 10, 2005 to Gregory H. Rau et al. and assigned to the U.S. Department of Energy discloses a method and apparatus for extracting and sequestering CO2 from a gas stream wherein hydrating the CO2 in the gas stream with an aqueous solution forms carbonic acid resulting in a CO2 depleted gas stream, and reacting carbonic acid with carbonate forms a waste stream solution of metal ions and bicarbonate. The waste stream is released into a disposal site comprising a large body of water. This process has several disadvantages because it has a low CO2 storage density and requires a large body of water for application. It also creates large amounts of carbonic acid changing the Ph and mineral composition of the body of water, affecting aquatic and plant life dependent on the body of water.
U.S. Pat. No. 7,132,090 issued Nov. 7, 2004 to Daniel Dziedzic et al. and assigned to General Motor Corp. discloses a process for removing carbon dioxide from a gaseous stream by diffusing gaseous carbon dioxide into water by passing the gaseous carbon dioxide through a microporous gas diffuser membrane and a catalyst specifically for carbon dioxide such as carbonic anhydrase to accelerate a conversion of the carbon dioxide to carbonic acid supported by a matrix. A mineral is added to the reaction so that a precipitate of carbonate salt is formed which can be stored for extended periods in the ground. However, this process requires multiple steps, and an extremely large microporous gas diffuser membrane to handle a volume of CO2 significant enough to be practical for the reduction and sequestering of greenhouse gases.
Tar sands and oil sands are a combination of sand (primarily silica), water, hydrocarbons and other chemicals, metals and minerals. They exist around the world, with preponderance in the North American continent. The hydrocarbons are in the form of bitumen which accounts for about 5 to 20% by weight of the deposit and is often attached to a water layer that surrounds a sand/rock/metal particle. The bitumen can be recovered in a variety of ways, which are generally categorized by one of two methods, either mining and surface processing or in situ processing.
Typically, an in situ tar sand recovery scheme involves either fire flooding or steam injection to heat the bitumen until its viscosity is lowered such that it flows from the sand matrix. Most popular is the steam method, where high pressure steam provides heat that helps to separate the bitumen (oil) from the water/sand matrix, and then a series of pumps, pipes and wells bring the bitumen to the surface for further processing. The high pressure steam is typically delivered through a perforated horizontal metal pipe forming a “steam trunk”, or a balloon of steam in an area. A second perforated horizontal tube for recovery of the excess water and oil products is located below the steam delivery tube, usually about 9 to 50 feet, comprising a system known as SAGD or Steam Assisted Gravity Drainage. While this process is effective and in common use, it has some serious drawbacks, such as primarily poor economics due to a ratio of oil produced to oil consumed, and water pollution and usage. The energy required to heat the steam is only marginally less than the energy recovered in the form of oil products. Substantial quantities of hot water and now post process mobilized oil are left in the ground, which have the potential to dissolve, mobilize or transport salts, metals including heavy metals, and other indigenous chemicals from their original naturally occurring locations to other geological locations including acquifers and other undesirable areas. Any improvement in the efficiency of the process, as categorized by energy consumption (i.e. oil recovery per unit of energy, e.g. barrels recovered per million BTUs) yield improvement, or product quality improvement should enhance the prospects for getting oil from these formations. Likewise, any reduction in the amount of steam or energy required to separate the oil from the water and sand matrix will be a welcome addition to the process, as it will increase the energy efficiency, lower the total amount of greenhouse gases generated and lower the amount of fresh water required to generate the steam, and therefore, reduce the amount of water effluent to the process that must be disposed of after recovery. Likewise, providing for a method of removing the residual oil from the formation and from recovered hot water is also a welcome addition to the process.
Several processes have been envisioned to improve the hydrocarbon separation from the sand matrix. Fyleman (U.S. Pat. No. 1,615,121) uses a dilute aqueous solution of alkali carbonate, hydroxide or silicate heated from 60° to 80° C. to help remove the oil from the sand matrix. Clark (U.S. Pat. No. 1,791,797) uses a polyvalent salt with an alkaline reagent to improve separation. U.S. Pat. No. 2,924,772 uses a diesel alkaline waste and water to help form layers for eventual separation. Willard, Sr. (U.S. Pat. No. 3,951,778) uses a warmed (40° C.-90° C.) silicate solution containing calcium and magnesium, surfactant and water to help with separation. Fischer (U.S. Pat. No. 2,903,407) also uses hydrocarbon based solvents and so on. These processes all rely on an above ground batch type mixing and contain compounds that may be undesirable in the end due to environmental concerns.